Power plant methods and apparatus

ABSTRACT

A hybrid power plant system including a gas turbine system and a coal fired boiler system inputs high oxygen content gas turbine flue gas into the coal fired boiler system, said gas turbine flue gas also including carbon dioxide that is desired to be captured rather than released to the atmosphere. Oxygen in the gas turbine flue gas is consumed in the coal fired boiler, resulting in relatively low oxygen content boiler flue gas stream to be processed. Carbon dioxide, originally included in the gas turbine flue gas, is subsequently captured by the post combustion capture apparatus of the coal fired boiler system, along with carbon diode generated by the burning of coal. The supply of gas turbine flue gas which is input into the boiler system is controlled using dampers and/or fans by a controller based on an oxygen sensor measurement and one or more flow rate measurements.

RELATED APPLICATIONS

The present application is a continuation of U.S. patent applicationSer. No. 15/172,024 which was filed on Jun. 2, 2016 and which waspublished as U.S. Patent Publication US 2017-0350319 A1 on Dec. 7, 2017and which is hereby expressly incorporated by reference in its entirety.

FIELD

The present application relates to power plant methods and apparatus,more particularly, to methods and apparatus for reducing CO2 intensity.

BACKGROUND

Power plants burning fossil fuels are large emitters of carbon dioxide.Coal and natural gas are the most widely used fossil fuels for powergeneration worldwide and in the US. When burned, coal of various typesreleases more CO2 per unit electricity generated than other fossil fuelsincluding natural gas. As a result, coal-fired power plants have thehighest CO2 intensity (CO2 emissions per unit of electricity output) ofall thermal power plants.

On the other hand, natural gas-fired, combustion turbine based powerplants have lower CO2 intensity than coal-fired plants. However, gasturbine (GT) exhaust typically has low CO2 concentration (4-5% vol) andhigh oxygen concentration (13-14% vol), compared to 12-13% CO2 and 5-6%oxygen for typical coal-fired power plants. The low CO2 concentration ofGT exhaust can lead to large equipment size and capital investment, andhigh oxygen concentration can result in accelerated degradation of theCO2 solvent and increased operating cost, for a post-combustion CO2capture (PCC) system for a gas-fired combustion turbine based powerplant.

Based on the above discussion, there is a need for new methods andapparatus for reducing CO2 intensity with regard to exhaust gasesgenerated in a gas fired combustion turbine.

SUMMARY

Various embodiments, in accordance with the present invention, includethe integration of GT exhaust with a coal-fired boiler, and by doing soutilize the remaining oxygen in the GT exhaust. Various exemplaryembodiments are directed to an integrated GT-Boiler system. The exhaustgas from the integrated GT-Boiler system will have similar O2 and CO2concentrations as those from typical coal-fired power plants, which canbe more cost effectively captured with available CO2 absorptiontechnology.

The integration of the GT and boiler, in accordance with the presentinvention, also effectively utilizes the waste heat of the GT exhaust.Therefore an exemplary novel integrated system, in accordance with thepresent invention, has higher plant efficiency than the combinedefficiency of a standalone coal-fired power plant and a standalonenatural gas-fired GT power plant.

An exemplary proposed integrated system, in accordance with the presentinvention, reduces the CO2 intensity of the power plant by the abovementioned thermal efficiency improvement and also by utilizing naturalgas which emits less CO2 per unit heating value than coal.

In a first configuration, in accordance with the present invention, theGT exhaust first goes through a heat recovery steam generator (HRSG).This exhaust after the HRSG of a gas turbine combined cycle plant (GTCC)is relatively cool (typically around 200F) and can be, and in variousembodiment is, introduced into a plurality of areas of a coal-firedpower plant. For example in one exemplary embodiment in accordance withthe first configuration, five streams of relatively cool HRSG outputexhaust are introduced into five different locations in a coal firedpower plant. This first configuration utilizes the oxygen and low gradewaste heat in the GTCC exhaust gas. The resulted flue gas from theboiler power plant can be, and is, effectively treated in a CO2absorption process for CO2 capture.

In a second configuration, in accordance with the present invention, hotexhaust gas directly from a simple cycle gas turbine (GT), without goingthrough a HRSG, is injected into the boiler plant, e.g., a coal-firedboiler plant. This exhaust gas from the GT, with temperature typicallyin the 900-1150 F range, is injected in streams, e.g., four streams,into the boiler plant, with the injection points being at selectedlocations where such high temperature and partially oxygen-depleted gascan be effectively utilized in the boiler. Essentially, this secondconfiguration utilizes the existing boiler as the heat recovery unitinstead of a having a new, separately installed HRSG as the heatrecovery unit. This second configuration utilizes the oxygen and thehigh temperature waste heat in the simple cycle GT exhaust gas, withoutthe need of a separate HRSG. The resulting flue gas from the boilerpower plant can be effectively treated in a CO2 absorption process forCO2 capture.

In various embodiments, oxygen rich exhaust gas from a gas turbine isinjected into a coal fired boiler system, said exhaust gas from the gasturbine including carbon dioxide that is desired to be captured. Oxygenin the gas turbine exhaust gas is consumed in the coal-fired boiler, andthe CO2, originally from the gas turbine exhaust, is output into theflue gas from the boiler. The CO2, originally from the gas turbineexhaust, is captured within a PCC system, along with CO2 generated fromthe burning of coal. It should be appreciated that the flue gas beingprocessed by the PCC has a lower oxygen content than the flue gas outputfrom the gas turbine, facilitating a more efficient and less expensivecapture of the gas turbine generated CO2.

In some embodiments, heat energy within the gas turbine exhaust gas iscaptured using a post gas turbine HRSG. In some embodiments, heat energywithin the gas turbine exhaust gas is used to heat inlet gas flowspertaining to the coal fired system. Thus the integrated natural gasturbine-coal fired boiler power plant system utilizes this energy togenerate power, which might have been otherwise lost and wasted.

Various features, methods, apparatus and/or embodiments, in accordancewith the present invention, can be applied to any power plants wherethere is (are) existing gas turbine unit(s) in the vicinity ofcoal-fired units, or power plants where there is space for building newGT or GTCC unit(s) that are integrated with the coal-fired units. Theproposed integration of GT and boiler is an effective way to reducecarbon intensity and extending the service life of existing coal powerplants, which, with a total installed capacity of over 300 GW, generatesmore power than any other types of power plants in the U.S.

An exemplary power system in accordance with some embodiments includes:a boiler system including: a boiler; an oxygen sensor; one or more gasturbine flue gas inputs including at least one of: i) a gas turbine fluegas boiler hopper input of said boiler or ii) a gas turbine flue gasmill air supply duct input which is included as part of a mill airsupply duct which supplies air to a mill which provides fuel to saidboiler; a gas turbine system; and a controller for controlling thesupply of gas turbine flue gas to said one or more gas turbine flue gasinputs of said boiler system based on an oxygen level measured by saidoxygen sensor.

An exemplary method of operating a system including a boiler system anda gas turbine system, the boiler system including a boiler, the turbinesystem including a gas turbine, in accordance with some embodiments,comprises: measuring an oxygen level in flue gas output by the boiler;operating a controller, during a first mode of operation during whichsaid boiler is active and said gas turbine is active, to control thesupply of gas turbine flue gas to a first gas turbine flue gas input ofsaid boiler system based on the measured oxygen level, said first fluegas input being one of: i) a gas turbine flue gas boiler hopper input ofa boiler, ii) a gas turbine flue gas burner air supply duct input whichsupplies air to a burner of said boiler, or iii) a gas turbine flue gasmill air supply duct input which is included as part of a mill airsupply duct which supplies air to a mill which provides fuel to saidboiler.

Numerous additional features, embodiments and benefits of the variousembodiments are discussed in the detailed description which follows.While various embodiments have been discussed in the summary above, itshould be appreciated that not necessarily all embodiments include thesame features and some of the features described above are not necessarybut can be desirable in some embodiments.

BRIEF DESCRIPTION OF THE FIGURES

FIG. 1 is a drawing of an exemplary integrated gas turbine-coal firedboiler system, in which cold gas turbine exhaust output from a heatrecovery steam generator is injected into boiler related flows inaccordance with an exemplary embodiment.

FIG. 2 is a drawing of an exemplary integrated gas turbine-coal firedboiler system, in which hot gas turbine exhaust is injected into boilerrelated flows in accordance with an exemplary embodiment.

FIG. 3A is a first part of a flowchart of an exemplary method ofoperating a system including a boiler system and a gas turbine system inaccordance with an exemplary embodiment.

FIG. 3B is a second part of a flowchart of an exemplary method ofoperating a system including a boiler system and a gas turbine system inaccordance with an exemplary embodiment.

FIG. 3 comprises the combination of FIG. 3A and FIG. 3B.

DETAILED DESCRIPTION

FIG. 1 is a drawing of an exemplary integrated gas turbine-boiler powerplant system 100 in accordance with an exemplary embodiment. Exemplarypower plant system 100 includes a boiler system 103 including a boiler104 and a gas turbine system 109 including a gas turbine 126. Exemplarysystem 100 includes mills 102, a boiler 104, a selective catalyticreduction (SCR) apparatus 106, an air heater (AH) 108, an electrostaticprecipitator/fabric filter (ESP/FF) 110, an induced draft (ID) fan 112,a flue-gas desulfurization (FGD) apparatus 114, a post-combustioncapture (PCC) apparatus 116, a first stack 118, a first damper 120, aforced draft (FD) fan 122, a primary air (PA) fan 124, a gas turbine(GT) 126, a HRSG 128, a booster fan 130, a second damper 134, a thirddamper 136, a fourth damper 138, a fifth damper 140, a sixth damper 142,a second stack 132, a third stack 133, a coal chute 144, a CO2 outletpipe 146, a natural gas inlet pipe 148, a milled coal feed 150, and aplurality of ducts or pipes (154, 156, 158, 160, 162, 164, 166, 168,170, 172, 173, 178 including first portion 178 a and second portion 178b, 182, 184, 186, 188, 190, 196, 198, 206 including first portion 206 aand second portion 206 b, 208 including first portion 208 a and secondportion 208 b, 209, 210 including first portion 210 a and second portion210 b, 211, 212 including first portion 212 a and second portion 212 b)coupled together as shown in FIG. 1.

Exemplary integrated gas turbine-boiler power plant system 100 furtherincludes a controller 401 for controlling operation of system 100, anoxygen sensor 444 for measuring oxygen level in a flue gas output by theboiler, a plurality of airflow measurement devices (420, 422, 424, 426,428, 430), e.g., a plurality of airflow meters, each airflow meterincluding airflow sensor, or a plurality of airflow sensors formeasuring flow rates at selected locations in the system, a boileron/off sensor 448 configured to indicate boiler operational status, anda gas turbine on/off sensor 452 configured to indicated gas turbineoperational status. Controller 401 determines a current mode ofoperation, processes outputs from various sensors, e.g., activationstatus sensors (448, 452), flow rate sensors (420, 422, 424, 426, 428,430), an oxygen measurement sensor 444, determines control, e.g.,desired GT flue gas input(s) into the boiler system in terms of whichinput(s) are to be used at a given time and/or GT flue gas injectionamounts for the selected inputs, the desired control position of dampers(134, 136, 138, 140, 142) at a given time to achieve the desired controleffects, and the desired throughput of fans (412, 414), and generatessends control signal to implement the desired control. In variousembodiments, GT flue gas input into the boiler system is determined as afunction of a measured oxygen level, e.g., in the flue gas 226 output bythe boiler 104.

Controller 401 receives a boiler active status signal via line 450.Controller 701 receives a gas turbine active status signal via line 454.Controller 701 receives an oxygen sensor measurement signal via line446. Controller 701 receives airflow rate measurement signals via lines(432, 434, 436, 438, 440, 442). Controller 701 sends controls signalsvia lines (402, 404, 406, 408, 410 412, 414, 414) to control theposition of the dampers and fans.

Coal 232 is fed to mills 102 via coal chute 144. Mills 102 receives thecoal 232 and mills the coal 232 generating milled coal 224, e.g.,pulverized coal, which is fed, via milled coal feed 150, to the burners152 of boiler 104. Burner air input stream 310 is received via burnerair input 204; over fire air stream 308 is received via over fire airinput 202. The burners 152 of boiler 104 burn the received milled coal224 generating steam, e.g., superheated steam, used to drive a steamturbine which spins a generator and generates electrical power, and theboiler outputs flue gas. Exhaust gas stream 226, the flue gas output, isoutput from boiler 104 and directed to SCR 106, via duct 154. The SCR106 processes the received exhaust gas stream 154, said processingincluding reducing nitrous oxides (NOx), e.g., into N₂ and water, andgenerates SCR output gas stream 228, which is fed to an inlet of AH 108,via duct 156. The AH 108 removes heat from the gas stream 228, at leastsome of the removed heat is transferred into gas streams being directedinto the boiler 108 and the mills 208.

The outlet gas stream 230 from AH 108 is directed to an inlet of ESP/FF110 via duct 158. The ESP/FF 110 reduces ash from the flue gas flowbeing processed, and fly ash and other waste products are recovered. Theoutlet gas stream 232 from ESP/FF 110 is directed to the inlet of ID fan112 via duct 160. The outlet gas stream 234 from ID fan 112 is directedto an inlet of FGD 114. The FGD 114 removes sulfur dioxide (SO2) fromthe flue gas flow being processed. Outlet gas stream 236 from FGD 114 isdirected to the inlet of PCC 116 via duct 164. The PCC 116 captures CO2from the flue gas flow being processed. An outlet gas stream 238 fromPCC 116 is directed to the inlet of stack 188 via duct 166. PCC 116 alsooutlets captured CO2 240 via CO2 outlet pipe 146. The captured CO2 canbe compressed and stored, e.g., underground, and/or may be utilized forother purposes that do not result in release to the atmosphere. Itshould be appreciated that some of the captured CO2 includes CO2 whichwas included in the cold GT exhaust injected gas flows (256, 290, 292,294, 296).

Gas turbine 126 receives natural gas 242 via gas inlet pipe 148. The gasturbine burns the received natural gas 242 and outputs hot GT exhaust244 via duct 168. Duct 168 directs the hot GT exhaust 244 to an input ofHRSG 128. HRSG 128 extracts heat from the received hot GT exhaust 244and outputs cold GT exhaust 246 into duct 170. Duct 170 is coupled tothe input of booster fan 130. Duct 172 is coupled to duct 170. A firstportion 248 of cold GT exhaust 246 is input to booster fan 130; and asecond portion 250 of cold GT exhaust 246 is directed down duct 172.

Duct 172 is coupled to an input of stack 132 and an inlet of duct 178. Afirst portion 252 of cold GT exhaust 250 is input to stack 132; a secondportion 254 of cold GT exhaust 250 is input to duct 178.

Cold GT exhaust stream 248 is input to booster fan 130 and output ascold GT exhaust stream 272 into duct 173. Duct 173 is coupled to theinput of stack 133 and to the inputs of ducts 206, 208, 210 and 212. Theoutputs of duct portions (206 a, 208 a, 210 a, 212 a), are coupled tothe inputs of dampers (136, 138, 140, 142), respectively. The outputs ofdampers (136, 138, 140, 142) are coupled to the inputs of duct portions(206 b, 208 b, 210 b, 212 b), respectively. Gas flow 272 is divided intogas flow 274 which proceeds down duct 173 and gas flow 276 which entersduct 212. Gas flow 274 is divided into gas flow 278 which proceeds downduct 173 and gas flow 280 which enters duct 210. Gas flow 278 is dividedinto gas flow 282 which proceeds down duct 173 and gas flow 284 whichenters duct 208. Gas flow 282 is divided into gas flow 286 whichproceeds down duct 173 and enters stack 133 and gas flow 288 whichenters duct 206.

Second cold GT exhaust gas injection stream 290 is output from damper136 into duct portion 206 b and is injected into the gas stream 270emerging from the PA fan 124 at input 214 of duct 190.

Third cold GT exhaust gas injection stream 292 is output from damper 138into duct portion 208 b and is injected into the gas stream 302 flowingtoward the mills 102, the injection being at input 216 of duct 209.

Fourth cold GT exhaust gas injection stream 294 is output from damper140 into duct portion 210 b and is injected into the gas stream 306forming gas stream 307 which will supply burner air as stream 310 andOFA air as stream 308, the injection being at input 218 of duct 196.

Fifth cold GT exhaust gas injection steam 296 is output from damper 142into duct portion 212 b and directed into the bottom of the furnace ofboiler 104 through water walls below the burners 152 via input 220.

The output of duct portion 178 a is coupled to an input to damper 134,and the output of damper 134 is coupled to first cold GT air injectionstream duct portion 178 b. First cold GT air injection stream ductportion 178 b is coupled to inlet 180 of air duct 182. Fresh air 258received via duct 182 is mixed in duct 182 with cold GT exhaust stream256 received via duct 178 to generate gas stream 260. The outlet of duct182 is coupled to an inlet of damper 120, and the outlet of damper 120is coupled to an inlet to FD fan 122. The outlet of FD fan 122 iscoupled to an inlet of duct 186, and the outlet of duct 186 is coupledto an inlet of AH 108. Duct 188 is also coupled duct 186. Gas stream 262is input to FD fan 122 and output as gas stream 264. A first portion 266of gas stream 264 is directed to an AH 108 inlet via duct 186; a secondportion 268 of gas stream 264 is directed to an input of PA fan 124 viaduct 188. Output gas stream 306, which corresponds to input gas stream266, emerges from air heater 108 and is directed via duct 196 towardburner air input 204 of boiler 104.

Duct 196 is coupled to an outlet of duct 210 and an inlet of duct 198.Within duct 196 AH output gas stream 306 is mixed with received fourthcooled GT exhaust stream 294, received via duct 210, to generate gasstream 307. A first portion 310 of gas stream 307 is directed to burnerinput 204 as the burner air stream, via burner air input duct 196; asecond portion 308 of gas stream 307 is directed to OFA input 202 viaduct 198.

Inlet gas flow with regard to the mills 102 will now be described. PAfan 124 receives gas flow 268, via duct 188, and outputs flow 270 intoduct 190. Duct 190 is coupled to duct 214 and duct 206. Gas stream 270is combined in duct 190, with second cold GT exhaust stream 290,received via duct 206, to generate gas stream 298. A first portion 300of gas stream 298 is input to AH 108 via duct 190; and a second portion302 of gas stream 298 is directed into mills inlet duct 209. The outletof mills inlet duct 209 is coupled to the mills air inlet of mills 102.Third cold GT exhaust stream injection duct 208 is coupled to duct 209.Gas stream 302 is combined in duct 209 with third cold GT exhaustinjection stream 292, which is received via duct 208 to generate gasstream 304. Duct 209 is further coupled to duct 211. Output gas stream306, which corresponds to inlet gas stream 300, emerges from AH 108, andis directed via duct 211 to duct 209. In duct 209, gas stream 304 iscombined with gas stream 306 to generate mills burner inlet air stream308.

Fifth cold GT exhaust stream 296 is directed via duct 212 directly intoinlet 220 in the bottom of the furnace of boiler 104 through water wallsbelow the burners 152.

In some embodiments, gas turbine 126 and HRSG 128 are part of a GTCCplant and mills 102, boiler 104, SCR 106, AH 108, ESP/FF 110, FGD 114and PCC 116 are part of a coal fired boiler plant. In some embodiments,the cold exhaust gas from the GTCC plant, e.g., in the range of around200 degrees F., is sent into the boiler plant. In some such embodiments,the range is, e.g., 150 to 250 degrees F. In Stream 1 256, the exhaustgas is sent from outlet of the HRSG 128 directly to the inlet of theforced draft (FD) fan 122 of the coal-fired boiler 104, with a damper134 to modulate the flow. The GT exhaust 256 will be mixed with freshair 258 at the inlet to the FD fan 122. The FD fan 122 supplies thecombustion air for the entire boiler 104.

In Stream 2 290, the GT exhaust is injected into the outlet of theprimary air (PA) fan 124 which provides air for the coal mills 102 andcarries the pulverized coal into the furnace through the burners 152. InStream 3 292, the GT exhaust will be injected into the Cold Air stream302 coming off the PA fan 124. In Stream 4 294, the GT exhaust isdirected to the secondary duct 196 which supplies burner air 310 andover-fire-air 308. In Stream 5 296, GT exhaust is ducted, via duct 212,directly into the bottom of the furnace through water walls below theburners 152.

In some embodiments, each of cold GT exhaust injection streams 2, 3, 4,5 (290, 292, 294, 296) is arranged individually. In some embodiments,each of cold GT exhaust injection streams 2, 3, 4, 5 (290, 292, 294,296) are arranged in combination with other streams. In someembodiments, some of cold GT exhaust injection streams 2, 3, 4, 5 (290,292, 294, 296) are arranged individually, while some of the cold GTexhaust injection streams 2, 3, 4, 5 (290, 292, 294, 296) are arrangedin combination with other streams.

In some embodiments, each of these streams (290, 292, 294, 296) is downstream of a booster fan, e.g., booster fan 130, and each stream (290,292, 294, 296) has a flow modulating damper, e.g. dampers (136, 138,140, 142), respectively. Any excess amount of exhaust from the GTCCsystem can be, and in various embodiments, is vented to the atmosphere,e.g., via stack 133.

In the example of system 100 of FIG. 1, there are five gas turbine fluegas inputs (180, 214, 216, 218, 220) which are used to input gas turbineflue gas, e.g., cooled gas turbine flue gas, into the boiler system 103.Gas turbine flue gas input 220 is a gas turbine flue gas boiler hopperinput of boiler 104. The gas turbine flue gas hopper input 220 is forreceiving gas turbine flue gas 296 and supplying the received gasturbine flue gas 296 into the boiler 104 at a location beneath theburner 152.

Gas turbine flue gas input 216 is a gas turbine flue gas mill air supplyduct input which is included as part of mill air supply duct 209 whichsupplies air to mill 102 which provides fuel 224 to boiler 104.

Gas turbine flue gas input 218 is a gas turbine flue gas burner airsupply duct input. Burner air supply duct 196 supplies air to the burner152 of the boiler 104 and the burner air supply duct 196 includes thegas turbine flue gas burner air supply duct input 218.

Controller 401 controls the supply of gas turbine flue gas to gasturbine flue gas inputs (180, 214, 216, 218, 220) of boiler system 103based on an oxygen level measured by oxygen sensor 444. Damper 142 islocated in gas turbine flue gas duct 212 connected to gas turbine fluegas boiler hopper input 220. In various embodiments, controller 401 isconfigured to control damper 410 to be in an open position during afirst mode of operation during which both the gas turbine 126 and theboiler 104 are active. Fans 122 and 124 blow air 258, e.g., fresh air,which is mixed with gas turbine flue gas, prior to the gas turbine fluegas reaching the boiler 104. In some embodiments, controller 401 isconfigured to control the throughput of one or both of fans (122 and124) as a function of the output of the oxygen sensor 444.

In some embodiments, the flue gas input 220 of said boiler hoppersupplies more gas turbine flue gas to the boiler system 103 than anyother gas turbine flue gas input (180, 214, 216, 218) supplies to theboiler system 103.

In various embodiments, the controller 401 is configured to controldampers (134, 136, 138, 140, 142) to isolate the boiler system 103 fromthe gas turbine system 109 when the boiler system 103 is active and thegas turbine system 109 is inactive. In some such embodiments, thecontroller 401 is further configured to isolate the boiler system 103from the gas turbine system 109 when the boiler system 103 is inactiveand the gas turbine system is active.

FIG. 2 is a drawing of an exemplary integrated gas turbine-boiler powerplant system 500 in accordance with an exemplary embodiment. Exemplarypower plant system 500 includes a boiler system 503 including a boiler504 and a gas turbine system 509 including a gas turbine 524. Exemplarysystem 500 includes mills 502, a boiler 504, a SCR 506, an air heater(AH) 508, an ESP/FF 510, an ID fan 512, a FGD 514, a PCC 516, a firststack 518, an FD fan 520, a PA fan 522, a gas turbine (GT) 524, a firstdamper 528, a second damper 530, a third damper 532, a fourth damper534, a fifth damper 536, a second stack 526, a coal chute 538, a CO2outlet pipe 540, a natural gas inlet pipe 542, a milled coal feed 544,and a plurality of ducts or pipes (546, 548, 550, 552, 554, 556, 558,560, 562 including a first portion 562 a and a second portion 562 b, 564including a first portion 564 a and a second portion 564 b, 566including a first portion 566 a and a second portion 566 b, 568including a first portion 568 a and a second portion 568 b, 578, 580,582, 584, 586, 588, 590, 592, 594, 596, 598) coupled together as shownin FIG. 2. Note that reference connection A 569 is used to indicate thatcutoff portions of duct portion 568 b are actually connected.

Exemplary integrated gas turbine-boiler power plant system 500 furtherincludes a controller 701 for controlling operation of system 500, anoxygen sensor 734 for measuring oxygen level in a gas, e.g., flue gas610 entering SCR 506, a plurality of airflow measurement devices (716,718, 720, 722, 724), e.g., a plurality of airflow meters, each airflowmeter including airflow sensor, or a plurality of airflow sensors formeasuring flow rates at selected locations in the system, a boileron/off sensor 738 configured to indicate boiler operational status, anda gas turbine on/off sensor 742 configured to indicated gas turbineoperational status. Controller 701 determines a current mode ofoperation, processes outputs from various sensors, e.g., activationstatus sensors (738, 742), flow rate sensors (716, 718, 720, 722, 724),a oxygen measurement sensor 734, determines control, e.g., desired GTflue gas input(s) into the boiler system in terms of which input(s) areto be used at a given time and/or GT flue gas injection amounts for theselected inputs, the desired control position of dampers (528, 530, 532,534, 536) at a given time to achieve the desired control effects, andthe desired throughput of fans (522, 524), and generates and sendscontrol signal(s) to implement the desired control. In variousembodiments, GT flue gas input into the boiler system is determined as afunction of a measured oxygen level. In various embodiments, controlledthroughput of fans (520, 522) is determined as a function of a measuredoxygen level and/or the determined mode of operation. Controller 701receives a boiler active status signal via line 740. Controller 701receives a gas turbine active status signal via line 744. Controller 701receives a oxygen sensor measurement signal via line 736. Controller 701receives airflow rate measurement signals via lines (724, 726, 728, 730,732). Controller 701 sends controls signals via lines (702, 704, 704,706, 710 712, 714) to control the position of the dampers and fans.

Exemplary integrated gas turbine-boiler power plant system 500 furtherincludes a controller 701, an oxygen sensor 734, a plurality of airflowmeasurement devices (716, 718, 720, 722, 724), e.g., a plurality ofairflow meters, each airflow meter including airflow sensor, or aplurality of airflow sensors, a boiler on/off sensor 738, and a gasturbine on/off sensor 742.

Coal 602 is fed to mills 502 via coal chute 538. Mills 502 receives thecoal 602 and mills the coal 602 generating milled coal 604, e.g.,pulverized coal, which is fed, via milled coal feed 544, to the burners505 of boiler 504. Burner air input stream 680 is received via burnerair input 509; over furnace air stream 682 is received via over furnaceair input 507. The burners 502 of boiler 504 burn the received milledcoal 604 generating steam, e.g., superheated steam, used to drive asteam turbine which spins a generator which generate electrical power.The burner 504 outputs flue gas. A first exhaust gas stream 608, whichis a flue gas output, is output from boiler 604 and directed to SCR 506,via duct 546. A second exhaust stream 606, which is an economizer bypassgas stream, is output from the boiler 504 and directed toward the SCR506 via duct 580 of the economizer bypass provided the damper 536 isopen. In some embodiments, duct 578 is included and fourth hot GTexhaust injection stream 652 may be, and sometimes is, directed downduct 578 as gas flow 652 b and into the economizer duct 580 of theeconomizer bypass, and toward the boiler 504 upstream of the economizer511, with the damper 536 in a closed position.

Gas stream 660 is an output stream from damper 536 into duct 582 of theeconomizer bypass. Gas stream 660 is combined with first exhaust gasboiler output steam 608 to form gas stream 610, which enters SCR 506. Insome embodiments, duct 578 and damper 536 are not included, and gasflows 606 and 660 are the same gas flow. Oxygen sensor 734 measures theoxygen level in gas flow stream 610.

The SCR 506 processes the received exhaust gas stream 610, saidprocessing including reducing nitrous oxides (NOx), e.g., into N₂ andwater, and generates SCR output gas stream 612, which is fed to an inletof AH 508, via duct 548. Air heater 508 removes heat from the receivedgas stream 612, at least some of the removed heat is transferred toinlet air streams being directed to the boiler 504 and the mills 502.The outlet gas stream 614 from AH 508 is directed to an inlet of ESP/FF510 via duct 550. The ESP/FF 510 reduces the amount of ash in the fluegas stream being processed, removing fly ash and other waste products.The outlet gas stream 616 from ESP/FF 510 is directed to the inlet of IDfan 512 via duct 552. The outlet gas stream 618 from ID fan 512 isdirected to an inlet of FGD 514. The FGD 514 removes sulfur dioxide(SO2) from the exhaust flue gas being processed. Outlet gas stream 620from FGD 514 is directed to the inlet of PCC 516 via duct 556. An outletgas stream 624 from PCC 516 is directed to the inlet of stack 518 viaduct 558. PCC 516 also outlets captured CO2 622 via CO2 outlet pipe 540.The captured CO2 can be compressed and stored, e.g., underground, and/ormay be utilized for other purposes that do not result in release to theatmosphere. It should be appreciated that some of the captured CO2includes CO2 which was included in the hot GT exhaust injected gas flows(646, 648, 650, 652).

Gas turbine 524 receives natural gas 626 via gas inlet pipe 542. The gasturbine 524 burns the received natural gas 626 and outputs hot GTexhaust 628, which is hot GT flue gas, via duct 560. Duct 560 is coupledto: an input of stack 526. Duct 560 is also coupled to an inlet of eachof: duct 562, duct 564, duct 566, and duct 568. The outputs of ductportions (562 a, 564 a, 566 a, 568 a) are coupled to the inputs ofdampers (528, 530, 532, 534), respectively. The outputs of dampers (528,530, 532, 534) are coupled to the inputs of duct portions (562 b, 564 b,566 b, 568 b), respectively. Hot GT exhaust gas flow 628 is divided intogas flow 630 which proceeds down duct 560 and gas flow 632 which entersduct 568. Gas flow 630 is divided into gas flow 634 which proceeds downduct 560 and gas flow 636 which enters duct 566. Gas flow 634 is dividedinto gas flow 638 which proceeds down duct 560 and gas flow 640 whichenters duct 564. Gas flow 638 is divided into gas flow 642 whichproceeds down duct 560 and enters stack 526 and gas flow 644 whichenters duct 562.

First hot GT exhaust gas injection stream 646 is output from damper 528into duct portion 562 b and is injected into the gas stream 674, viainput 570 of duct 592, flowing toward the mills 502, forming combinedgas stream 686.

Second hot GT exhaust gas injection stream 648 is output from damper 530into duct portion 564 b and is injected into the gas stream 677, viainput 572 of duct 596, forming combined gas stream 678, which willsupply burner air 680 and OFA air 682.

Third hot GT exhaust gas injection stream 650 is output from damper 532into duct portion 568 b and directed into the bottom of the furnace ofboiler 504 through water walls below the burners 505, via input 574.

Fourth hot GT exhaust gas injection stream 652 is output from damper 534into duct portion 568 b and directed toward the boiler 504. In someembodiments, duct 576 is included and duct 578 is not included andfourth hot GT exhaust injection stream 652 is input to the boiler 504 atinput 576 a above the economizer 511, via duct 576 as gas flow 652 a. Insome embodiments, duct 578 is included and fourth hot GT exhaustinjection stream 652 is directed down duct 578, as gas flow 652 b, andinto economizer duct 580 of the economizer bypass at input 576 b, andgas flow 652 b is directed toward boiler 504 and gas flow 652 b is inputto the boiler 504 slightly above the economizer 511, with the damper 536in a closed position.

Fresh air 662, received via duct 584, is directed to the inlet of FD fan520. The outlet of FD fan 520 is coupled to an inlet of duct 586, andthe outlet of duct 586 is coupled to an inlet of AH 508. Duct 588 isalso coupled duct 586. Inlet air stream 662 is output from FD fan 520 asair stream 664. A first portion 666 of air stream 664 is directed to anAH 108 inlet via duct 586; a second portion 668 of air stream 664 isdirected to an input of PA fan 522 via duct 588. Air heater output airstream 677, which corresponds to air heater input air stream 666,emerges from air heater 508 and is directed via duct 596 toward burnerair input 509 of boiler 504.

Duct 596 is coupled, via input 572, to an outlet of duct 564, and duct596 is also coupled to an inlet of duct 598. Within duct 596 AH outputair stream 677 is mixed with received second hot GT exhaust injectionstream 648, received from duct 564 via input 572, to generate gas stream678. A first portion 680 of gas stream 678 is directed to burner input509 as the burner air stream, via burner air input duct 596; a secondportion 682 of gas stream 678 is directed to OFA input 507 via duct 598.

Inlet gas flow with regard to the mills 502 will now be described. PAfan 522 receives air flow 668, via duct 588, and outputs air flow 670into duct 590. Duct 590 is coupled to duct 592. A first portion 672 ofair stream 670 is input to AH 108 via duct 590; and a second portion 674of air stream 670 is directed into mills inlet duct 592. The outlet ofmills inlet duct 592 is coupled to the mills air inlet of mills 502.Mills duct 592 includes inlet 570 which couples duct 562 to duct 592.Air stream 674 is combined in duct 592 with first hot GT exhaustinjection stream 646, which is received via input 570 of duct 592 fromduct 562, to generate gas stream 686. Duct 592 is further coupled toduct 594. Output air stream 684, which corresponds to inlet air stream672, emerges from AH 508, and is directed via duct 594 to duct 592. Induct 592, air stream 686 is combined with gas stream 684 to generatemills burner inlet air stream 689.

Third hot GT exhaust stream 650 is directed via duct 566 directly intothe bottom of the furnace of boiler 504 through water walls below theburners 505 via input 574.

In some embodiments, the hot GT exhaust gas, which is (900-1150 F) isintroduced into the boiler plant, e.g., as injection streams (646, 648,650, 652) is in the range of 900-1150 degrees F. Due to its hightemperature of the hot GT exhaust gas, a booster fan is not used;instead the GT 524 is operated at a significant backpressure, e.g., 20inches of H2O or higher backpressure, depending on where the GT exhaustis introduced.

Hot GT exhaust steam 1 646 is injected and mixed into the cold airstream for the coal mills 502, e.g., first hot GT exhaust injectionstream 646 is mixed with cold air stream 674 to form gas stream 686which is directed toward the mills 502. Hot GT exhaust stream 2 648 isinjected and mixed into the secondary air stream 677 downstream of theair preheater (AH) 508 to form air stream 678 which suppliesover-fire-air (OFA) 682 and burner air 680. Hot GT exhaust stream 3 650is ducted directly into the bottom of the furnace through water wallsbelow the burners 505 via input 574. In some embodiments, hot GT exhauststream 4 652 is introduced, as gas flow 652 a or as gas stream 652 b, tothe upstream of the economizer 511, a part of the boiler 504 watercircuit. In some embodiments, hot GT exhaust gas injection stream 4 652is injected directly into the main flue gas path upstream of theeconomizer as gas stream 652 a. Alternatively, in some otherembodiments, hot GT exhaust gas injection stream 4 652 is injected, asgas flow 652 b via duct 578, into a flue gas bypass duct (580,582)connecting the flue gas flow path from economizer inlet to the SCRinlet. The flue gas bypass duct (580, 582) is common for boiler unitsequipped with SCR. In the second arrangement in which flow 652 b isinjected into duct 580, a damper 536 is used to prevent the GT exhaustfrom entering the SCR 506 directly. In the first arrangement in whichflow 652 a is injected into boiler 504, damper 536 is not included.

Each of hot GT exhaust injection streams (stream 1 646, stream 2 648,stream 3 650, stream 4 652) can be arranged individually or incombination with other streams. Each of these streams (646, 648, 650,652) has a flow modulating damper (528, 530, 532, 534), respectively.Any excess amount of exhaust from the GTCC system is vented to theatmosphere, e.g., via stack 526.

In the example of system 500 of FIG. 2, there are four gas turbine fluegas inputs (570, 572, 574, 576 a or 576 b) which are used to input gasturbine flue gas, e.g., hot gas turbine flue gas, into the boiler system503. Gas turbine flue gas input 574 is a gas turbine flue gas boilerhopper input of boiler 504. The gas turbine flue gas hopper input 574 isfor receiving gas turbine flue gas 650 and supplying the received gasturbine flue gas 650 into the boiler 504 at a location beneath theburners 505.

Gas turbine flue gas input 570 is a gas turbine flue gas mill air supplyduct input which is included as part of mill air supply duct 592 whichsupplies air to mill 502 which provides fuel 604 to boiler 504.

Gas turbine flue gas input 572 is a gas turbine flue gas burner airsupply duct input. Burner air supply duct 596 supplies air to the burner505 of the boiler 504 and the burner air supply duct 596 includes thegas turbine flue gas burner air supply duct input 572.

Controller 701 controls the supply of gas turbine flue gas to gasturbine flue gas inputs (570, 572, 574, 576 a or 576 b) of boiler system503 based on an oxygen level measured by oxygen sensor 734. Damper 532is located in gas turbine flue gas duct 566 connected to gas turbineflue gas boiler hopper input 574. In various embodiments, controller 701is configured to control damper 532 to be in an open position during afirst mode of operation during which both the gas turbine 524 and theboiler 504 are active. Fans 520 and 522 blow air 258, e.g., fresh air,which can be, and sometimes is, subsequently mixed with gas turbine fluegas, prior to the mixture including the gas turbine flue gas reachingthe boiler 504. In some embodiments, controller 701 is configured tocontrol the throughput of one or both of fans (520 and 522) as afunction of the output of the oxygen sensor 734. In some embodiments,controller 701 is configured to control the throughput of one or both offans (520 and 522) as a function of the determined mode of operation,e.g. with less fresh air being supplied during a first mode of operationin which both the gas turbine and the boiler are active than anothermode in which the boiler is active and the gas turbine is inactive.

In some embodiments, the flue gas input 574 of said boiler hoppersupplies more gas turbine flue gas to the boiler system 503 than anyother gas turbine flue gas input (570, 572, 576 a or 576 b) supplies tothe boiler system 503.

In various embodiments, the controller 701 is configured to controldampers (528, 530, 532, 534) to isolate the boiler system 503 from thegas turbine system 509 when the boiler system 503 is active and the gasturbine system 509 is inactive. In some such embodiments, the controller701 is further configured to isolate the boiler system 503 from the gasturbine system 509 when the boiler system 503 is inactive and the gasturbine system 509 is active.

FIG. 3, comprising the combination of FIG. 3A and FIG. 3B, is aflowchart 800 of an exemplary method of operating a power systemincluding a boiler system, e.g., a coal fired boiler system, and a gasturbine system, in accordance with an exemplary embodiment. Operationstarts in step 802 in which at least a portion of the power system ispowered on and initialized. For example, a controller is powered on andinitialized and at least one of the boiler system and the gas turbinesystem is powered on and initialized. Operation proceeds from step 802to steps 804, 810 and 812, which may be performed in parallel.

In step 804 the controller determines a current mode of operation. Step804 includes steps 806 and 808. In step 806 the controller is operatedto receive an operation status input from the boiler system, e.g., asignal indicating whether the boiler system is active or inactive. Instep 808 the controller is operated to receive an operation status inputfrom the gas turbine system, e.g., a signal indicating whether the gasturbine system is active or inactive. In one exemplary embodiment, instep 804, the controller determines whether the current mode ofoperation is: a first mode of operation in which the boiler is activeand the gas turbine is active, a second mode of operation in which saidboiler is active and said gas turbine is not active or a third module ofoperation in which said boiler is inactive and said gas turbine isactive. Operation proceeds from step 804 to step 814.

Returning to step 810, in step 810 the oxygen level in the flue gasoutput by the boiler is measured. In various embodiments the oxygenlevel is determined based on a signal received from an oxygen sensorwhich is placed in a boiler flue gas stream flow at a location beforethe boiler flue gas enters an SCR. In some embodiments, multiple oxygensensors are placed in the system and used by the controller.

Returning to step 812, in step 812 flow rates are measured from one ormore flow meters. In some embodiments, the flow meters include flow ratesensors which are placed in each of the possible gas turbine flue gasinput paths from which gas turbine flue gas may be, and sometimes is,injected into the boiler system.

In step 814 if the determination of step 804 is that the current mode ofoperation is the first mode of operation in which said boiler is activeand said gas turbine is active, then operation proceeds from step 814,via connecting node A 826, to steps 828 and 842; otherwise, operationproceeds from step 814 to step 816.

In step 816, if the current mode of operation is a mode of operation inwhich said boiler is active and said gas turbine is not active, e.g., asecond mode of operation, then operation proceeds from step 816 to step818 and step 819; otherwise, operation proceeds from step 816 to step820.

In step 818 the controller is operated during the mode of operation inwhich said boiler is active and said gas turbine is not active to closedampers between the gas turbine system and said boiler system to isolatethe inactive gas turbine system from the active boiler system. In step819 the controller is operated during the mode of operation in whichsaid boiler is active and said gas turbine is not active to control thethroughput of one or more fans. Operation proceeds from steps 818 and819 to connecting node B 850.

In step 820, if the current mode of operation is a mode of operation inwhich said boiler is inactive and said gas turbine is inactive, e.g., athird mode of operation, then operation proceeds from step 820 to step822; otherwise, operation proceeds from step 820 to connecting node B850.

In step 822, the controller is operated, during the mode of operation inwhich said boiler is not active and said gas turbine is active, to closedampers between the gas turbine system and said boiler system to isolatethe inactive boiler system from the active gas turbine system. Step 822includes step 824 in which the controller, during the mode of operationin which said boiler is not active and said gas turbine is active, toprevent the supply of gas turbine flue gas to first flue gas input ofsaid boiler system. Operation proceeds from step 822 to connecting nodeB 850. In some embodiments, during the third mode of operation in whichthe gas turbine is active and the boiler system is inactive, flue gasfrom the gas turbine system is directed to an additional carbon recoveryand/or pollution control system, e.g., a system which is more expensiveto operate than the carbon control recovery and pollution control systemincluded in the boiler system.

Returning to step 814, in step 814, if the current mode of operation isa first mode of operation in which said boiler is active and said gasturbine is active, then operation proceeds from step 814, via connectingnode A 826 to steps 828 and 842. In step 828 the controller is operatedto control the supply of gas turbine flue gas to one or more gas turbineflue gas inputs based on the measured oxygen content level. Step 820includes one or more or all of steps 830, 832 and 834. In step 830 thecontroller is operated to control the supply of gas turbine flue gas toa first gas turbine flue gas input of said boiler system based on themeasured oxygen content level, said first flue gas input being one of:i) a gas turbine flue gas boiler hopper input of a boiler, ii) a gasturbine flue gas burner air supply duct input which supplies air to aburner of said boiler or iii) a gas turbine flue gas mill air supplyduct input, which is included as part of a mill air supply duct, whichsupplies air to a mill which provides fuel to said boiler. Step 830includes step 836 in which the controller is operated to control theposition of a first damper used to control the supply of gas turbineflue gas to the first gas turbine flue gas input to be in an openposition.

In step 832 the controller is operated to control the supply of gasturbine flue gas to a second gas turbine flue gas input of said boilersystem based on the measured oxygen content level, said second flue gasinput being one of: i) a gas turbine flue gas boiler hopper input of aboiler, ii) a gas turbine flue gas burner air supply duct input whichsupplies air to a burner of said boiler or iii) a gas turbine flue gasmill air supply duct input, which is included as part of a mill airsupply duct, which supplies air to a mill which provides fuel to saidboiler, said second flue gas input being different from said first fluegas input. Step 832 includes step 838 in which the controller isoperated to control the position of a second damper used to control thesupply of gas turbine flue gas to the second gas turbine flue gas inputto be in an open position.

In step 834 the controller is operated to control the supply of gasturbine flue gas to a third gas turbine flue gas input of said boilersystem based on the measured oxygen content level, said third flue gasinput being one of: i) a gas turbine flue gas boiler hopper input of aboiler, ii) a gas turbine flue gas burner air supply duct input whichsupplies air to a burner of said boiler or iii) a gas turbine flue gasmill air supply duct input, which is included as part of a mill airsupply duct, which supplies air to a mill which provides fuel to saidboiler, said third flue gas input being different from said first fluegas input and said second flue gas input. Step 838 includes step 840 inwhich the controller is operated to control the position of a thirddamper used to control the supply of gas turbine flue gas to the thirdgas turbine flue gas input to be in an open position.

In step 842 the controller is operated to control the throughput of oneor more fans. In various embodiments, the throughput of a fan iscontrolled by controlling an inlet damper included in an inlet ductprior to the fan inlet, e.g., controlling the position of the damper,and/or by controlling a variable speed drive, e.g., controlling fanmotor speed. Step 842 includes one or both of steps 844 and step 846. Instep 844 the controller is operated to control the throughput of a firstfan, e.g., a primary air (PA) fan, which supplies air which is mixedwith turbine flue gas prior to the combined flue including the flue gasreaching the boiler. In step 846 the controller is operated to controlthe throughput of a second fan, e.g., a forced draft (FD) fan, whichsupplies air which is mixed with turbine flue gas prior to the combinegas including the flue gas reaching the boiler.

Operation proceeds from steps 828 and 842 to connecting node B 850.Operation proceeds from connecting node B 850 to the input of step 804,in which a current mode of operation is determined. Steps 804, 810 and812 are repeated on a recurring basis. In various embodiments, therepeat rates for step 804, 810 and 812 are different.

The flowchart 300 of FIG. 3 will now be described for an exemplaryembodiment in which the power system is power system 100 of FIG. 1including a boiler system including boiler 104 and a gas turbine systemincluding gas turbine 126. In step 804 controller 401 determines thecurrent mode of operation based on a received boiler status input signalreceived on boiler status input signal line B_(ON/OFF) 450 and based onreceived gas turbine status input signal received gas turbine statusinput signal line GT_(ON/OFF) 452, which are received by controller 401in steps (806, 808), respectively from status indicators devices (448,452), respectively. The determined mode of operation is one of: a firstmode is which both the boiler 104 and the gas turbine 126 are active, asecond mode in which the boiler 104 is active and the gas turbine 126 isinactive, or a third mode in which the gas turbine 126 is active and theboiler 104 is inactive.

In step 810 the oxygen level in the flue gas output 226 by the boiler104 is measured based on a sensor measurement signal on oxygen sensorline V_(O2) 446, e.g., a voltage level, from oxygen sensor 444 which isreceived and processed by controller 401, said processing includingcomparing the voltage level to a predetermined oxygen sensor modelmapping oxygen content level to voltage level.

In step 812 the controller 401 measures flow rates based on receivedflow rate signals received on flow rate signal lines (R1 432, R2 434, R3436, R4 438, R5 440, R6 442) from airflow rate measurement devices (420,422, 424, 426, 428, 430), respectively. In some embodiments, airflowmeasurement devices (420, 422, 424, 426, 428, 430) are airflow meterswith each meter including an airflow rate sensor. In some otherembodiments, airflow measurement devices (420, 422, 424, 426, 428, 430)are airflow sensors with the processing of the sensor outputs todetermined measured rates being performed within the controller 401.

Operation control steps 814, 816 and 820 are performed by the controller401 based on the determination of step 804.

In step 818 controller 401 generates and sends control signals viacontrol lines (C1 402, C2 404, C3 406, C4 408, C5 410) to close dampers(134, 136, 138, 140, 142), respectively, to isolate the inactive gasturbine system from the active boiler system.

In step 819 the controller 401 generates and send control signals oncontrol lines (C7 412, C8 414) to fans (FD fan 122, PA fan 124) tocontrol the throughput of the fans. In various embodiments, each fan(122, 124) is initially set at a predetermined fixed level correspondingto the second mode of operation in which the boiler 104 is active andthe gas turbine 126 is inactive and therefore no gas turbine flue gas issupplied to the boiler. Subsequently fan throughputs are adjusted, e.g.,slightly based on oxygen sensor measurement information. In some suchembodiments, the rates of step 819 are higher than the rates of step842, in which gas turbine flue gas is being input to the boiler.

In step 822 the controller 401 generates and sends control signals viacontrol lines (C1 402, C2 404, C3 406, C4 408, C5 410) to close dampers(134, 136, 138, 140, 142), respectively, to isolate the inactive boilersystem from the active gas turbine system.

In step 828 the controller 401 determines desired gas turbine flue gasinput injection levels for each of gas turbine flue gas inputs (180,214, 216, 218, 220), which are inputs the boiler system, based on themeasured oxygen level. Controller 401 generates and sends control signalvia control lines (C1 402, C2 404, C3 406, C4 408, C5 410) to controlthe operation of dampers (134, 136, 138, 140, 142), respectively. Thecontrol of step 828 includes controlling one or more dampers (134, 136,138, 140, 142) to be in an open position, which allows gas turbine fluegas to be input into the boiler system. In some embodiments, a damper iscontrolled to be either in a fully closed or fully open position. Insome embodiments, a damper may be, and sometimes is controlled to be ina fully closed position, a fully open position, or a partially openposition. In some such embodiments, control supports a fixed number ofpredetermined partially open conditions for a damper, e.g., 8 or lessdifferent partially open conditions. In some embodiments, controlsupports a continuous range of partially open conditions for a damper.

Consider that the first gas turbine flue gas input is gas turbine fluegas hopper input 220 of boiler 104. In step 830, including step 836,controller 401 generates and sends a control signal on control signalline C5 410 to control the position of damper 142 to be in an openposition, which results in flue gas 296 being input to flue gas hopperinput 220 of boiler 104.

Further consider that the second gas turbine flue gas input is the gasturbine flue gas burner air supply duct input 218 which supplies air tothe burners 152 of said boiler 104. In step 832, including step 838,controller 401 generates and sends a control signal on control signalline C4 408 to control the position of damper 140 to be in an openposition, which results in flue gas 294 being input into gas turbineflue gas burner air supply duct input 218 of duct 196.

Further consider that the third gas turbine flue gas input is the gasturbine flue gas mill air duct supply duct input 216, which is includedas part of a mill air duct 209 which supplies air to mill 102 whichprovides fuel 224 said boiler 104. In step 834, including step 840,controller 401 generates and sends a control signal on control signalline C3 406 to control the position of damper 138 to be in an openposition, which results in flue gas 292 being input into the gas turbineflue gas mill air duct supply duct input 216 of a mill air duct 209.

In some embodiments, controller 401 generates and sends a control signalvia control signal line C2 404 to control the position of damper 136 tobe in an open position, which results in gas turbine flue gas 290 beinginput into gas turbine flue gas input 214 of duct 190.

In some embodiments, controller 401 generates and sends a control signalvia control signal line C1 402 to control the position of damper 134 tobe in an open position, which results in gas turbine flue gas 256 beinginput into gas turbine flue gas input 180 of duct 182.

In step 842, including steps 844 and 846, controller 401 determinesdesired throughputs for FD fan 122 and PA fan 124, generates and sendscontrol signals on control lines (C7 412, C8 414), respectively tocontrol the throughputs of the fans (122, 124), respectively, whichsupply air 258 which is mixed with gas turbine flue gas prior to themixture including the flue gas reaching the boiler 104. In variousembodiments, the fan throughputs of step 842 are adjusted, e.g.,lowered, with respect to gas turbine inactive mode of operation of step819, since with the gas turbine active some or all of the fresh supplyair 258 can be, and sometimes is, replaced by gas turbine flue gas.

The flowchart 300 of FIG. 3 will now be described for an exemplaryembodiment in which the power system is power system 500 of FIG. 2including a boiler system including boiler 504 and a gas turbine system509 including gas turbine 524. In step 804 controller 701 determines thecurrent mode of operation based on a received boiler status input signalreceived on boiler status input signal line B_(ON/OFF) 740 and based onreceived gas turbine status input signal received gas turbine statusinput signal line GT_(ON/OFF) 744, which are received by controller 701in steps (806, 808), respectively from status indicators devices (738,742), respectively. The determined mode of operation is one of: a firstmode is which both the boiler 504 and the gas turbine 524 are active, asecond mode in which the boiler 504 is active and the gas turbine 524 isinactive, or a third mode in which the gas turbine 524 is active and theboiler 504 is inactive.

In step 810 the oxygen level in the flue gas output 610 by the boiler504, prior to the SCR 506, is measured based on a sensor measurementsignal on oxygen sensor line V_(O2) 736, e.g., a voltage level, fromoxygen sensor 734 which is received and processed by controller 701,said processing including comparing the voltage level to a predeterminedoxygen sensor model mapping oxygen content level to voltage level.

In step 812 the controller 701 measures flow rates based on receivedflow rate signals received on flow rate signal lines (R1 724, R2 726, R3728, R4 730, R5 732) from airflow rate measurement devices (716, 718,720, 722, 724), respectively. In some embodiments, airflow measurementdevices (716, 718, 720, 722, 724) are airflow meters with each meterincluding an airflow rate sensor. In some other embodiments, airflowmeasurement devices (716, 718, 720, 722, 724) are airflow sensors withthe processing of the sensor outputs to determine measured rates beingperformed within the controller 701. In some embodiments, the airflowrate sensors' measurement signals are input to different channels of ameter included within controller 701, e.g., with multiplexing occurringbetween the channels.

Operation control steps 814, 816 and 820 are performed by the controller701 based on the determination of step 804.

In step 818 controller 701 generates and sends control signals viacontrol lines (C1 702, C2 704, C3 706, C4 708) to close dampers (528,530, 532, 534), respectively, to isolate the inactive gas turbine systemfrom the active boiler system.

In step 819 the controller 701 generates and send control signals oncontrol lines (C6 712, C7 714) to fans (FD fan 520, PA fan 522) tocontrol the throughput of the fans. In various embodiments, each fan(520, 524) is initially set at a predetermined fixed level correspondingto the second mode of operation in which the boiler 504 is active andthe gas turbine 524 in inactive and since the gas turbine 524 isinactive no gas turbine flue gas is supplied to the boiler in the secondmode of operation. In some such embodiments, the fan throughput ratesare adjusted slightly, e.g., a change of 25% or less, from the initialnominal rates based on an oxygen sensor measurement. In someembodiments, the rates of step 819 are higher than the rates of step842, in which gas turbine flue gas is being input to the boiler.

In step 822 the controller 701 generates and sends control signals viacontrol lines (C1 702, C2 704, C3 706, C4 708) to close dampers (528,530, 532, 534), respectively, to isolate the inactive boiler system fromthe active gas turbine system.

In step 828 the controller 701 determines desired gas turbine flue gasinput injection levels for each of gas turbine flue gas inputs (570,572, 574, 652 a or 652 b), which are inputs the boiler system, based onthe measured oxygen level. Controller 701 generates and sends controlsignal via control lines (C1 702, C2 704, C3 706, C4 708) to control theoperation of dampers (528, 530, 532, 534), respectively. The control ofstep 828 includes controlling one or more dampers (528, 530, 532, 534)to be in an open position, which allows gas turbine flue gas to be inputinto the boiler system. In some embodiments, a damper is controlled tobe either in a fully closed or fully open position. In some embodiments,a damper may be, and sometimes is controlled to be in a fully closedposition, a fully open position, or a partially open position. In somesuch embodiments, control supports a fixed number of predeterminedpartially open conditions for a damper, e.g., 16 or less differentpartially open conditions. In some embodiments, control supports acontinuous range of partially open conditions for a damper.

Consider that the first gas turbine flue gas input is gas turbine fluegas hopper input 574 of boiler 504. In step 830, including step 836,controller 701 generates and sends a control signal on control signalline C3 706 to control the position of damper 532 to be in an openposition, which results in flue gas 650 being input to flue gas hopperinput 574 of boiler 504.

Further consider that the second gas turbine flue gas input is the gasturbine flue gas burner air supply duct input 572 which supplies air toa burner of said boiler 504. In step 832, including step 838, controller701 generates and sends a control signal on control signal line C2 704to control the position of damper 530 to be in an open position, whichresults in flue gas 648 being input into gas turbine flue gas burner airsupply duct input 572 of duct 596.

Further consider that the third gas turbine flue gas input is the gasturbine flue gas mill air duct supply duct input 570, which is includedas part of a mill air duct 592 which supplies air to mill 502 whichprovides fuel 604 said boiler 504. In step 834, including step 840,controller 701 generates and sends a control signal on control signalline C1 702 to control the position of damper 528 to be in an openposition, which results in flue gas 646 being input into the gas turbineflue gas mill air duct supply duct input 570 of the mill air duct 592.

In some embodiments, controller 701 generates and sends a control signalvia control signal line C4 708 to control the position of damper 534 tobe in an open position, which results in gas turbine flue gas 652 beinginput into gas turbine flue gas input 576 a of boiler 504 as flue gas652 a or which results in gas turbine flue gas 652 being input into gasturbine flue gas input 576 b of duct 580 as flue gas 652 b, dependingupon the particular embodiment of the boiler system.

In some embodiments, controller 701 generates and sends a control signalvia control signal line C5 710 to control the position of damper 536 tobe in an closed position, which results in gas turbine flue gas 652 bentering economizer bypass duct 580 at input 576 b and being directedtoward boiler 504 where it enters the boiler 504 upstream of theeconomizer 511.

In step 842, including steps 844 and 846, controller 701 determinesdesired throughputs for FD fan 520 and PA fan 522, generates and sendscontrol signals on control lines (C6 712, C7 714), respectively tocontrol the throughputs of the fans (520, 522), respectively, whichsupply air 662, e.g., fresh air, which is mixed with gas turbine fluegas prior to the mixed gas including the fresh air and the flue gasreaching the boiler. In various embodiments, the fan throughputs of step842 are adjusted, e.g., lowered, with respect to gas turbine inactivemode of operation of step 819, since with the gas turbine active some orall of the air 662 can be, and sometimes is replaced by gas turbine fluegas, i.e., not as much fresh air 662 is needed to be supplied to theburner system since some or all of the fresh air is replaced by flue gasfrom the gas turbine system.

Various additional features of the present invention will now bedescribed in connection with exemplary apparatus/system embodiments. Theapparatus/system embodiments are only exemplary in nature and thefeatures may be used in any number of combinations.

A power system (100 or 500) embodiment 1 includes: a boiler system (103or 503) including: a boiler (104 or 504); an oxygen sensor (444 or 734);and one or more gas turbine flue gas inputs ((180, 214, 216, 218, 220)or (570, 572, 574, 576 a or 576 b))) including at least one of: i) a gasturbine flue gas boiler hopper input (220 or 574) of said boiler (104 or504) or ii) a gas turbine flue gas mill air supply duct input (216 or570) which is included as part of a mill air supply duct (209 or 592)which supplies air to a mill (102 or 502) which provides fuel (224 or604) to said boiler (104 or 504); a gas turbine system (109 or 509); anda controller (401 or 701) for controlling the supply of gas turbine fluegas to said one or more gas turbine flue gas inputs ((180,214, 216, 218,220) or (570, 572, 574, 576 a or 576 b)) of said boiler system (103 or503) based on an oxygen level measured by said oxygen sensor (444 or734).

A power system embodiment 2 including the power system embodiment 1,wherein the boiler system (103 or 503) includes: a burner (152 or 505);and at least said gas turbine flue gas boiler hopper input (220 or 574)for receiving gas turbine flue gas (296) and supplying said received gasturbine flue gas (296) into said boiler (104 or 504) at a locationbeneath the burner (152 or 505).

A power system embodiment 3 including the power system embodiment 2,wherein said boiler system (103 or 503) further includes: a burner airsupply duct (196 or 596) which supplies air to a burner (152 or 505) ofsaid boiler (104 or 504), said burner air supply duct (196 or 596)including a gas turbine flue gas burner air supply duct input (218 or572).

A power system embodiment 4 including the power system embodiment 2,wherein said boiler system (103 or 503) includes both the gas turbineflue gas boiler hopper input (220 or 574) of said boiler and the gasturbine flue gas mill air supply duct input (216 or 570).

A power system embodiment 5 including the power system embodiment 2wherein the power system embodiment 2 further includes: a first damper(142 or 532) in a first gas turbine flue gas duct (212 or 566) connectedto said gas turbine flue gas boiler hopper input (220 or 574); and

wherein said controller (401 or 701) is configured to control the firstdamper (142 or 532) to be in an open position during a first mode ofoperation during which both said gas turbine (126 or 524) and saidboiler (104 or 504) are active.

A power system embodiment 6 including the power system embodiment 5wherein the power system embodiment 5 further includes: a fan ((122 or124) or (520 or 522) which blows air (258 or 584) which is mixed withgas turbine flue gas prior to the gas turbine flue gas reaching theboiler (104 or 504); and wherein said controller (401 or 701) is furtherconfigured to control the throughput of the fan (PA fan (124 or 522) orFD fan (122 or 520)) as a function of the output of said oxygen sensor(444 or 734).

A power system embodiment 7 including the power system embodiment 5,wherein said flue gas input of said boiler hopper (220 or 574) suppliesmore gas turbine flue gas to said boiler system (103 or 503) than anyother gas turbine flue gas input ((180, 214, 216, 218) or (570, 572, 576a or 576 b)) supplies to said boiler system (103 or 503).

A power system embodiment 8 including the power system embodiment 2,wherein said controller (401 or 701) is further configured to controldampers ((134, 136, 138, 140, 142) or (528, 530, 532, 534)) to isolatesaid boiler system (103 or 503) from said gas turbine system (109 or509) when said boiler system (103 or 503) is active and said gas turbinesystem (109 or 509) is inactive.

A power system embodiment 9 including the power system embodiment 8,wherein said controller (401 or 701) is further configured to controlsaid dampers ((134, 136, 138, 140, 142) or (528, 530, 532, 534)) toisolate said boiler system (103 or 503) from said gas turbine system(109 or 509) when said boiler system (103 or 503) is inactive and saidgas turbine system (109 or 509) is active.

Various additional features of the present invention will now bedescribed in connection with exemplary method embodiments. The methodembodiments are only exemplary in nature and the features may be used inany number of combinations.

A method embodiment 1 of operating a system (100 or 500) including aboiler system (103 or 503) and a gas turbine system (109 or 509), theboiler system (103 or 503) including a boiler (104 or 504), the gasturbine system (109 or 509) including a gas turbine (524), the methodincluding: measuring an oxygen level in flue gas output by the boiler(104 or 504); operating a controller (401 or 701), during a first modeof operation during which said boiler (504) is active and said gasturbine (524) is active, to control the supply of gas turbine flue gasto a first gas turbine flue gas input of said boiler system based on themeasured oxygen level, said first flue gas input being one of: i) a gasturbine flue gas boiler hopper input (220 or 574) of a boiler (104 or504), ii) a gas turbine flue gas burner air supply duct input (210 or572) which supplies air to a burner (152 or 505) of said boiler (104 or504), or iii) a gas turbine flue gas mill air supply duct input (216 or570) which is included as part of a mill air supply duct (209 or 592)which supplies air to a mill (102 or 502) which provides fuel (224) tosaid boiler (104 or 504).

A method embodiment 2 including the method of method embodiment 1,wherein operating the controller (401 or 701), during the first mode ofoperation includes operating the controller (401 or 701) to control aposition of a first damper used to control the supply of gas turbineflue gas to the first gas turbine flue gas input to be in an openposition.

A method embodiment 3 including the method of method embodiment 2, themethod of method embodiment 3 further including: operating thecontroller to control the throughput of a fan (PA fan or FD fan) whichsupplies air which is mixed with gas turbine flue gas prior to the gasturbine flue gas reaching the boiler.

A method embodiment 4 including the method of method embodiment 2,wherein said controller further controls during the first mode ofoperation a supply of gas turbine flue gas to a second gas turbine fluegas input of said boiler system based on the measured oxygen level, thesecond flue gas input being one of: i) a boiler hopper input of aboiler, ii) a burner air supply duct which supplies air to a burner ofsaid boiler, or iii) a mill air supply duct which supplies air to a millwhich provides fuel to said boiler, said second flue gas input beingdifferent from said first flue gas input.

A method embodiment 5 including the method of method embodiment 4,wherein said first flue gas input is said gas turbine flue gas boilerhopper input and said second flue gas input is one of the gas turbineflue gas burner air supply duct input or the gas turbine flue gas millair supply duct input.

A method embodiment 6 including the method of method embodiment 5,wherein said controller further controls during the first mode ofoperation a supply of gas turbine flue gas to a third gas turbine fluegas input of said boiler system based on the measured oxygen level, thethird flue gas input being the gas turbine flue gas mill air supply ductinput, said second flue gas input being different from said first fluegas input.

A method embodiment 7 including the method of method embodiment 1, themethod of method embodiment 7 further including: operating thecontroller, during a second mode of operation during which said boileris not active and said gas turbine is active, to prevent the supply ofgas turbine flue gas to the first flue gas input of said boiler system.

A method embodiment 8 including the method of method embodiment 1, themethod of method embodiment 8 further including: operating thecontroller, during a second mode of operation during which said boileris active and said gas turbine is not active to close dampers betweenthe gas turbine system and said boiler system to isolate the inactivegas turbine system from the active boiler system.

A method embodiment 9 including the method of method embodiment 8, themethod of method embodiment 9 further including: operating thecontroller, during a third mode of operation during which said boiler isnot active and said gas turbine is active to close said dampers betweenthe gas turbine system and said boiler system to isolate the inactiveboiler system from the active gas turbine system.

Numerous additional variations on the methods and apparatus of thepresent invention described above will be apparent to those skilled inthe art in view of the above description of the invention. Suchvariations are to be considered within the scope of the invention.

What is claimed is:
 1. A power system comprising: a boiler systemincluding: a boiler; an oxygen sensor; and one or more gas turbine fluegas inputs including at least one of: i) a gas turbine flue gas boilerhopper input of said boiler or ii) a gas turbine flue gas mill airsupply duct input which is included as part of a mill air supply ductwhich supplies air to a mill which provides fuel to said boiler; a gasturbine system; and a controller for controlling the supply of gasturbine flue gas to said one or more gas turbine flue gas inputs of saidboiler system based on an oxygen level measured by said oxygen sensor.2. The power system of claim 1, wherein the boiler system includes: aburner; and at least said gas turbine flue gas boiler hopper input forreceiving gas turbine flue gas and supplying said received gas turbineflue gas into said boiler at a location beneath the burner.
 3. The powersystem of claim 2, wherein said boiler system further includes: a burnerair supply duct which supplies air to a burner of said boiler, saidburner air supply duct including a gas turbine flue gas burner airsupply duct input.
 4. The power system of claim 2, wherein said boilersystem includes both the gas turbine flue gas boiler hopper input ofsaid boiler and the gas turbine flue gas mill air supply duct input. 5.The power system of claim 2, further including a first damper in a firstgas turbine flue gas duct connected to said gas turbine flue gas boilerhopper input; and wherein said controller is configured to control thefirst damper to be in an open position during a first mode of operationduring which both said gas turbine and said boiler are active.
 6. Thepower system of claim 5, further comprising: a fan which blows air whichis mixed with gas turbine flue gas prior to the gas turbine flue gasreaching the boiler; and wherein said controller is further configuredto control the throughput of the fan as a function of the output of saidoxygen sensor.
 7. The power system of claim 5, wherein said flue gasinput of said boiler hopper supplies more gas turbine flue gas to saidboiler system than any other gas turbine flue gas input supplies to saidboiler system.
 8. The power system of claim 2, wherein said controlleris further configured to control dampers to isolate said boiler systemfrom said gas turbine system when said boiler system is active and saidgas turbine system is inactive.
 9. The power system of claim 8, whereinsaid controller is further configured to control said dampers to isolatesaid boiler system from said gas turbine system when said boiler systemis inactive and said gas turbine system is active.